Exhibit 99.1

 

Rex Energy Reports Second Quarter 2013 Operational and Financial Results

 

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Average daily production from oil and NGLs reached a record level of 4.4 MBoe/d

 

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Placed into sales the two-well Brace West pad in the Warrior North Prospect; combined 5-day sales rate of 2.7 Mboe/d with 745 BOPD condensate and an combined 25-day rate of 2.3 Mboe/d with 680 BOPD condensate; average 72% liquids

 

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Completed first “Super Rich” Upper Devonian well, the Burgh 2HD; produced 1,270 BTU gas with 53% liquids

 

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Most recent “Super Rich” Marcellus well, the Grubbs 2H, produced 1,337 BTU gas with 58% liquids

 

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Placed into sales first three wells in the Warrior South Prospect with combined 30-day sales rate of 4.8 Mboe/d

 

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First Illinois Basin horizontal well produced at a peak 24-hour sales rate of 367 BOPD

STATE COLLEGE, PA., August 6, 2013 (GLOBE NEWSWIRE) – Rex Energy Corporation (Nasdaq: REXX) today announced its second quarter 2013 operational and financial results.

Second Quarter Financial Results

Operating revenues from continuing operations for the three and six months ended June 30, 2013 were $55.4 million and $102.8 million, respectively, which represents an increase of 83% and 60% over the same periods in 2012, respectively. Commodity revenues, including cash-settled derivatives, were $52.6 million and $97.2 million for the three and six months ended June 30, 2013, respectively, an increase of 59% and 42%, over the comparable periods of 2012, respectively. Commodity revenues, including cash settled derivatives, from oil and natural gas liquids (NGLs) represented 54% of total commodity revenues, including cash-settled derivatives, for both the three and six months ended June 30, 2013, respectively.

Lease operating expense (LOE) from continuing operations was $13.1 million, or $1.67 per Mcfe for the quarter, a 13% decrease on a per unit basis compared to the same period in 2012. For the six months ended June 30, 2013, LOE was approximately $26.5 million, or $1.81 per Mcfe, which represents a 1% decrease on a per unit basis when compared to the same period in 2012. During the first six months of 2012, the company incurred approximately $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee.

Cash general and administrative (G&A) expenses from continuing operations, a non-GAAP measure, were $6.6 million for the three months ended June 30, 2013, which represents an 11% decrease on a per unit basis as compared to the same period in 2012. For the six months ended June 30, 2013, cash G&A expenses from continuing operations were $13.2 million, a 2% decrease on a per unit basis as compared to the same period in 2012. A reconciliation of cash G&A expenses to GAAP G&A expenses for the three and six months ended June 30, 2013, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.

Income from continuing operations attributable to common shareholders for the three months ended June 30, 2013 was $13.2 million, or $0.25 per fully diluted share. Income from continuing operations attributable to common shareholders for the six months ended June 30, 2013 was $10.4 million, or $0.20 per fully diluted share. Adjusted net income, a non-GAAP measure, for the three months ended June 30,

 

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2013 was $7.5 million, or $0.14 per share. Adjusted net income for the six months ended June 30, 2013 was $12.8 million, or $0.24 per share. A reconciliation of adjusted net income to GAAP net income for the second quarter of 2013, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.

EBITDAX from continuing operations, a non-GAAP measure, was $33.3 million for the second quarter and $59.3 million for the first six months of 2013. This was an increase of 85% over the second quarter of 2012 and an increase of 50% over the first six months of 2012. A reconciliation of EBITDAX to GAAP net income, as well as a discussion of the uses of the measure, is presented in the financial highlights attached to this release.

Production Update

Second quarter 2013 production volumes were 86.1 MMcfe/d, an increase of 38% over the second quarter of 2012 and 14% over the first quarter of 2013, consisting of 59.9 MMcf/d of natural gas and 4.4 Mboe/d of oil and NGLs. Oil and NGLs accounted for 30% of net production during the second quarter and increased by 19% over the first quarter of 2013. Second quarter 2013 production of 86.1 MMcfe/d was within the company’s previously announced guidance of 84.0 – 88.0 MMcfe/d. As previously reported, the company placed its first three wells in its Warrior South Prospect into sales later than anticipated due to infrastructure constraints. Rex Energy estimates that second quarter production was reduced by an estimated 2.3 MMcfe/d due to these constraints. After adjusting for the impact of these delays, the company’s quarterly production would have been approximately 88.4 MMcfe/d.

Second Quarter 2013 Capital Investments

For the second quarter of 2013, the company made operational capital investments of approximately $67.6 million, of which $49.3 million was used to fund Marcellus and Ohio Utica operations and $18.3 million was used to fund conventional drilling, water flood enhancement and ASP projects in the Illinois Basin. The Marcellus and Ohio Utica capital investment funded the drilling of 13 gross (8.5 net) wells, fracture stimulation of seven gross (5.5 net) wells, placing 10 gross (7.5 net) wells into sales and other projects related to drilling and completing wells in the Appalachian Basin. The Illinois Basin capital investment funded the drilling of five gross (five net) wells, fracture stimulation of eight gross (eight net) wells, placing eight gross (eight net) wells into sales and other projects related to drilling and completing wells.

In addition to operational capital investments, investments for leasing and proved property acquisitions were $7.7 million and capitalized interest was $1.8 million for the second quarter of 2013. Further details are provided below in the land update.

Operational Update

Note: Unless specifically stated otherwise in this operational update, all numbers are gross and all well results assume full ethane recovery

 

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Appalachian Basin – Butler Operated Area, Pennsylvania

In the Butler Operated Area, the company drilled six gross (4.2 net) wells in the second quarter of 2013, with five gross (3.5 net) wells fracture stimulated and four gross (2.8 net) wells placed into sales. The company had 14 gross (9.8 net) wells drilled and awaiting completion as of June 30, 2013.

The company placed into sales the JRGL 3H during the second quarter of 2013. The JRGL 3H was drilled to a total measured depth of 9,963 feet with a lateral length of 4,506 feet and was completed using the company’s 150’ “Super Frac” design with a total of 30 stages. Based on composition analysis, the gas being produced is approximately 1,301 BTU.

The company also placed into sales the Bricker 1H during the second quarter of 2013. The Bricker 1H was drilled to a total measured depth of 9,731 feet with a lateral length of 3,945 feet and was completed using the company’s 150’ “Super Frac” design with a total of 26 stages. Based on composition analysis, the gas being produced is approximately 1,204 BTU.

The company completed its sixth “Super Rich” Marcellus well during the second quarter of 2013, the Grubbs 2H. The well, which has a lateral length of 3,183 feet, was completed utilizing the company’s 150’ per stage “Super Frac” design with a total of 21 stages and placed into sales in May 2013. Based on composition analysis, the gas being produced is approximately 1,337 BTU, further delineating the company’s previously identified “Super Rich” line.

During the second quarter, the company completed the Burgh 2HD, the company’s third Upper Devonian Burkett well and first “Super Rich” Upper Devonian Burkett well. The well was drilled to a total measured depth of 8,223 feet with a horizontal lateral length of 2,447 feet and was completed in 15 stages using the company’s 150’ per stage “Super Frac” design. The well was placed into sales in July 2013. Based on composition analysis, the gas being produced is approximately 1,270 BTU.

Also during the second quarter, the company completed its fourth Upper Devonian Burkett Shale well, the Stebbins 2H, and is waiting to place the well into sales. During the second quarter, the company also drilled its fifth Upper Devonian Burkett Shale well, the Perry Township 1HD and is currently completing the well. The Perry Township 1HD will be placed into sales during the third quarter. By the end of 2013, the company expects to have seven Upper Devonian Burkett wells flowing into sales. Two of these wells, the Burgh 2HD and the Perry Township 1HD, lie within the company’s “Super Rich” area.

 

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The table below lists, where available, the 5-day and 30-day sales rates for the company’s recent completions.

 

5-Day Sales Rate (Average Per Well)1
Well Name		Target Formation		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (Mcfe/d)				Total – Adjusted to 4,000’ Lateral				% Liquids				Total  – Ethane Rejection (Mcfe/d)
JRGL 3H		Marcellus			2,930				19				583				6,541				5,806				55	%			4,601
Bricker 1H		Marcellus			2,964				5				425				5,541				5,618				47	%			3,987
Wack 9H		“Super Rich” Marcellus			2,506				18				532				5,805				6,022				57	%			4,071
Grubbs 2H		“Super Rich” Marcellus			1,829				27				395				4,356				5,474				58	%			3,024
Drushel 6HD		Upper Devonian			3,748				12				580				7,302				7,237				49	%			5,206
Burgh 2HD		“Super Rich” Upper Devonian			2,138				11				390				4,545				7,429				53	%			3,216

 

30-Day Sales Rate (Average Per Well)1
Well Name		Target Formation		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (Mcfe/d)				Total – Adjusted to 4,000’ Lateral				% Liquids				Total – Ethane Rejection (Mcfe/d)
JRGL 3H		Marcellus			2,834				17				564				6,317				5,608				55	%			4,441
Bricker 1H		Marcellus			2,908				9				417				5,462				5,538				47	%			3,937
Wack 9H		“Super Rich” Marcellus			2,313				8				491				5,306				5,504				56	%			3,706
Grubbs 2H		“Super Rich” Marcellus			1,618				13				349				3,791				4,764				57	%			2,613
Drushel 6HD		Upper Devonian			3,558				10				551				6,928				6,866				49	%			4,936

 

Total Operated Area – Butler County, PA
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Sales				Wells Awaiting Completion
YTD 2013			11				17				11				12
FY 2013 Forecast			19				24				23				15

Appalachian Basin – Warrior North Prospect, Carroll County, Ohio

To date during 2013, Rex Energy has drilled three gross (three net) wells in the Warrior North Prospect, with four gross (four net) wells fracture stimulated and four gross (four net) wells placed into sales. The company expects to have three gross (three net) wells awaiting completion at the end of 2013.

The Brace West 1H, located in Carroll County, Ohio, was placed into sales from its 60-day resting period in July 2013 and produced at a five-day sales rate of 1,464 Boe/d (48% NGLs, 31% gas, 20% condensate) and a natural gas shrink of 36%. The well went on to average a 25-day sales rate of 1,140 Boe/d (44% NGLs, 28% gas, 28% condensate) and a natural gas shrink of 36%. The well produced with an average casing pressure of 2,434 psi during the five-day sales period on an average 18/64 inch choke and 1,932 psi during the average 25-day sales period on an average 18/64 inch choke. The well was drilled to a total

 

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measured depth of 12,109 feet with a lateral length of approximately 4,178 feet and was completed in 27 stages, using the company’s “Super Frac” completion technique. Based on composition analysis, the gas being produced is approximately 1,298 BTU.

The Brace West 2H, located in Carroll County, Ohio, was placed into sales from its 60-day resting period in July 2013 and produced at a five-day sales rate of 1,260 Boe/d (39% NGLs, 26% gas, 36% condensate) and a natural gas shrink of 36%. The well went on to average a 25-day sales rate of 1,135 Boe/d (41% NGLs, 28% gas, 31% condensate) and a natural gas shrink of 36%. The well produced with an average casing pressure of 1,739 psi during the five-day sales period on an average 24/64 inch choke and 1,602 psi during the average 25-day sales period on an average 23/64 inch choke. The well was drilled to a total measured depth of 12,425 feet with a lateral length of approximately 4,658 feet and was completed in 30 stages, using the company’s “Super Frac” completion technique. Based on composition analysis, the gas being produced is approximately 1,286 BTU.

As previously reported, the company placed into sales the two-well G. Graham pad during the second quarter. The G. Graham 1H produced at a five-day sales rate of 1,710 Boe/d, a 30-day sales rate of 1,257 Boe/d and a 60-day rate of 1,042 Boe/d. During the 60-day sales period, the well produced with an average casing pressure of 1,339 psi on a 24/64 inch choke. The company continues to evaluate the results of the G. Graham 2H and will provide an update on its findings once the review is complete.

The table below lists, where available, the 5-day and 30-day sales rates for the company’s recent completions.

 

5-Day Sales Rate (Average Per Well)
Well Name		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (BOE/d)				% Liquids				Total – Ethane Rejection (BOE/d)
G. Graham 1H			3,075				497				701				1,710				70	%			1,417
Brace West 1H			2,751				296				709				1,464				69	%			1,164
Brace West 2H			1,939				448				488				1,260				74	%			1,045

 

25-day and 30-Day Sales Rate (Average Per Well)
Well Name		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (BOE/d)				% Liquids				Total – Ethane Rejection (BOE/d)
G. Graham 1H1			2,508				266				572				1,256				67	%			1,017
Brace West 1H2			1,944				315				501				1,140				72	%			928
Brace West 2H2			1,864				355				469				1,135				73	%			929

 

1	30-day rate

2	25-day rate

Appalachian Basin – Warrior South Prospect, Guernsey, Noble & Belmont Counties, Ohio

During the second quarter of 2013, the company placed into sales its first three wells in the Warrior South Prospect. The Noble 1H, located in Noble County, Ohio, produced at a five-day sales rate of 1,783 Boe/d and a 30-day sales rate of 1,469 Boe/d. The Guernsey 2H, located in Noble County, Ohio, produced at five-day sales rate of 1,764 Boe/d and a 30-day sales rate of 1,812 Boe/d. The Guernsey 1H, located in Noble County, Ohio, produced at a five-day sales rate of 1,646 Boe/d and a 30-day sales rate of 1,518 Boe/d.

 

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The company has completed drilling on the five-well J. Anderson pad in the Warrior South Prospect. The wells were drilled to an average lateral length of approximately 4,250 feet and are expected to be placed into sales near the end of 2013. With the completion of drilling of the fifth J. Anderson well, the rig moved back to the Warrior North Prospect to begin drilling operations on the three-well Ocel pad.

The table below lists, where available, the 5-day and 30-day sales rates for the company’s recent completions.

 

5-Day Sales Rate (Average Per Well)
Well Name		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (BOE/d)				% Liquids				Total – Ethane Rejection (BOE/d)
Noble 1H			4,694				238				763				1,783				56	%			1,329
Guernsey 2H			4,450				247				775				1,764				58	%			1,335
Guernsey 1H			4,159				228				724				1,646				58	%			1,245
Average			4,434				238				754				1,731				57	%			1,303

 

30-Day Sales Rate (Average Per Well)
Well Name		Natural Gas (Mcf/d)				Condensate (Bbls/d)				NGLs (Bbls/d)				Total – Ethane Recovery (BOE/d)				% Liquids				Total – Ethane Rejection (BOE/d)
Noble 1H			3,985				158				648				1,469				55	%			1,083
Guernsey 2H			4,688				214				816				1,812				57	%			1,361
Guernsey 1H			4,059				192				615				1,484				54	%			1,106
Average			4,244				188				693				1,588				55	%			1,183

 

Total Operated Area – Ohio Utica Shale
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Sales				Wells Awaiting Completion
YTD 2013			8				4				7				5
FY 2013 Forecast			11				9				12				3

Appalachian Basin – Well Cost Reduction

In the Appalachian Basin, Rex Energy has achieved its goal of reducing the costs to drill and complete wells in the Appalachian Basin by approximately 5% in 2013. This was accomplished through a combination of operational efficiencies and negotiated price reductions on service costs. Rex Energy is continuing to pursue additional cost saving initiatives and anticipates further well cost reductions when a full scale development program is initiated.

Appalachian Basin – Westmoreland, Clearfield and Centre Counties, Pennsylvania

In the company’s non-operated area in Westmoreland County, Pennsylvania, where WPX Energy serves as the operator, WPX drilled three wells and placed into sales one well during the second quarter of 2013. WPX Energy currently plans to drill an additional seven wells, fracture stimulate 14 wells and place into sales nine wells in 2013. WPX Energy estimates that at the end of 2013, four wells will be awaiting completion and five wells will be shut in for their resting period.

 

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In the company’s non-operated Westmoreland, Clearfield and Centre counties, Pennsylvania, the combined average production for a recent 5-day period was 48.1 MMcfe/d.

 

Total Non-Operated Area – Westmoreland, Clearfield and Centre Counties, PA
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Sales				Wells Awaiting Completion
YTD 2013			4				0				1				11
FY 2013 Forecast			11				14				10				4

Illinois Basin – Conventional

In the Illinois Basin, the company is continuing the conventional drilling and re-completion program it commenced in 2012 to increase its oil production. In the second quarter of 2013, the company drilled five vertical step out wells, performed completion or re-completion operations on eight wells and placed eight wells into sales.

The company has also completed its first horizontal well in the Illinois Basin. The well was drilled to a lateral length of approximately 1,200 feet and was fracture stimulated with nine stages using our “Super Frac” completion design. The well produced at a peak 24-hour sales rate of 367 gross BOPD and a peak 30-day sales rate of 222 gross BOPD. The company plans to drill one additional horizontal well in the Illinois Basin during 2013 as well as three additional vertical step-out wells in the same region as the horizontal wells to further delineate its acreage position.

 

Total Operated Area – Illinois Conventional Program
		Wells Drilled				Wells Fracture Stimulated				Wells Placed Into Sales				Wells Awaiting Completion
YTD 2013			13				20				16				2
FY 2013 Forecast			20				30				30				0

Land Update

During the second quarter of 2013, the company spent approximately $7.7 million of capital related to leasing and acreage acquisitions in the Appalachian and Illinois Basin. In the Butler Operated area of the Appalachian Basin, the company leased approximately 1,700 gross (1,100 net) acres during the second quarter of 2013, increasing its total leasehold in the region to approximately 71,700 gross (50,200 net) acres. Since the beginning of 2013, the company has added approximately 4,600 gross (2,600 net) acres in the Butler Operated Area. The company’s current plan is to target a total acreage position of approximately 74,000 gross (52,000 net) acres in the Butler Operated Area by the end of 2013. In the Ohio Utica, the company added approximately 600 net acres, increasing its total leasehold in the region to approximately 21,000 net acres. Lastly, in the Illinois Basin, the company added approximately 7,000 net acres in Indiana, increasing its total operated leasehold in the region to approximately 33,700 net acres.

Liquidity Update

In April 2013, the company completed an offering of an additional $100 million in aggregate principal amount of 8.875% senior notes (“Senior Notes”) due 2020 in a private placement. The Senior Notes were

 

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issued at an issue price of 105% of par plus accrued interest from December 12, 2012. The net proceeds of approximately $102.8 million plus accrued interest, after deducting the initial purchasers’ discount and estimated offering expenses, was used to fund a portion of 2013 capital expenditures and for general corporate purposes. As of June 30, 2013, the company had approximately $69 million of cash and no outstanding borrowings under its senior credit facility.

Third Quarter and Full Year 2013 Guidance

Rex Energy is providing its guidance for the third quarter and maintaining its full year 2013 guidance ($ in millions):

 

		3Q2013		Full Year 2013
Production		97.0 - 100.0 MMcfe/d		90.5 - 94.5 MMcfe/d
Lease Operating Expense		$17.0 - $18.5		$58 - $62
Cash G&A		$7.2 - $8.2		$26 - $29
Operational Capital Expenditures1		—		$255 - $275

 

1	Land acquisition expense and capitalized interest is not included in the operational capital expenditures budget

Conference Call Information

Management will host a live conference call and webcast on Wednesday, August 7, 2013 at 10:00 a.m. Eastern to review second quarter financial results and operational highlights. All financial results included in this release or discussed on the conference call will remain subject to our independent auditor’s review. The telephone number to access the conference call is (866) 437-1772. Presentation slides containing reference materials for the call and webcast will be available on the company’s website, www.rexenergy.com, under the Investor Relations tab. The replay of the event and reference materials will be available on the company’s website through September 7, 2013.

About Rex Energy Corporation

Rex Energy, headquartered in State College, Pennsylvania, is an independent oil and gas exploration and production company operating in the Appalachian and Illinois Basins within the United States. The company’s strategy is to pursue its higher potential exploration drilling prospects while acquiring oil and natural gas properties complementary to its portfolio.

Forward-Looking Statements

Except for historical information, statements made in this release, including those relating to the timing and nature of Marcellus, Upper Devonian, and Utica shale development plans; drilling and completion schedules; anticipated fracture stimulation activities; potential liquids composition; expected dates for placement of wells into sales; activities of our joint venture partners, WPX Energy; leasing plans; conventional expansion plans and plans for horizontal drilling in the Illinois Basin; and the company’s financial guidance, plans for capital expenditures and projections for 2013 are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may contain words such as “expected”, “expects”, “scheduled”, “planned”, “plans”, “anticipates” or similar words. These statements are based on management’s experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management’s assumptions and the company’s future performance are

 

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subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):

 

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economic conditions in the United States and globally;

 

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domestic and global demand for oil, NGLs and natural gas;

 

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volatility in oil, NGL, and natural gas pricing;

 

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new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations;

 

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the geologic quality of the company’s properties with regard to, among other things, the existence of hydrocarbons in economic quantities;

 

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uncertainties inherent in the estimates of our oil and natural gas reserves;

 

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our ability to increase oil and natural gas production and income through exploration and development;

 

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drilling and operating risks;

 

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the success of our drilling techniques in both conventional and unconventional reservoirs;

 

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the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;

 

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the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled;

 

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the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;

 

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the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;

 

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the effects of adverse weather or other natural disasters on our operations;

 

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competition in the oil and gas industry in general, and specifically in our areas of operations;

 

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changes in our drilling plans and related budgets;

 

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the success of prospect development and property acquisition;

 

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the success of our business and financial strategies, and hedging strategies;

 

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conditions in the domestic and global capital and credit markets and their effect on us;

 

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the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity; and

 

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uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome.

The company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on the company’s risks and uncertainties is available in the company’s filings with the Securities and Exchange Commission.

*    *    *    *    *

For more information, please contact:

Mark Aydin

Manager, Investor Relations

(814) 278-7249

maydin@rexenergy.com

 

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REX ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in Thousands, Except Share and Per Share Data)

 

		June 30, 2013 (Unaudited)				December 31, 2012
ASSETS
Current Assets
Cash and Cash Equivalents		$	69,194			$	43,975
Accounts Receivable			28,012				24,980
Taxes Receivable			1,396				6,429
Short-Term Derivative Instruments			8,410				12,005
Assets Held For Sale			—				2,279
Inventory, Prepaid Expenses and Other			1,284				1,316
Total Current Assets			108,296				90,984
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties			598,731				485,448
Unevaluated Oil and Gas Properties			178,958				165,503
Other Property and Equipment			59,416				50,073
Wells and Facilities in Progress			104,751				92,913
Pipelines			6,958				6,116
Total Property and Equipment			948,814				800,053
Less: Accumulated Depreciation, Depletion and Amortization			(167,233	)			(146,038	)
Net Property and Equipment			781,581				654,015
Deferred Financing Costs and Other Assets – Net			12,625				10,029
Equity Method Investments			18,823				16,978
Long-Term Derivative Instruments			1,777				704
Total Assets		$	923,102			$	772,710
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable		$	39,346			$	31,134
Accrued Expenses			36,802				22,421
Short-Term Derivative Instruments			1,554				1,389
Current Deferred Tax Liability			968				539
Liabilities Related to Assets Held for Sale			—				52
Total Current Liabilities			78,670				55,535
8.875% Senior Notes Due 2020			350,000				250,000
Premium (Discount) on Senior Notes			3,245				(1,742	)
Senior Secured Line of Credit and Long-Term Debt			2,675				991
Long-Term Derivative Instruments			420				1,510
Long-Term Deferred Tax Liability			30,339				23,625
Other Deposits and Liabilities			5,472				5,675
Future Abandonment Cost			26,172				24,822
Total Liabilities			496,993				360,416
Stockholders’ Equity
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,578,394 shares issued and outstanding on June 30, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012			52				52
Additional Paid-In Capital			453,127				451,062
Accumulated Deficit			(28,690	)			(39,595	)
Rex Energy Stockholders’ Equity			424,489				411,519
Noncontrolling Interests			1,620				775
Total Stockholders’ Equity			426,109				412,294
Total Liabilities and Owners’ Equity		$	923,102			$	772,710

 

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REX ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in Thousands, Except per Share Data)

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2013				2012				2013				2012
OPERATING REVENUE
Oil, Natural Gas and NGL Sales		$	51,444			$	27,699			$	92,384			$	59,181
Field Services Revenue			3,840				2,514				10,345				4,820
Other Revenue			76				44				100				89
TOTAL OPERATING REVENUE			55,360				30,257				102,829				64,090
OPERATING EXPENSES
Production and Lease Operating Expense			13,092				10,972				26,492				23,272
General and Administrative Expense			7,782				5,774				15,578				11,185
Loss on Disposal of Assets			1,502				69				1,493				95
Impairment Expense			105				273				170				3,066
Exploration Expense			2,225				1,213				4,269				2,305
Depreciation, Depletion, Amortization and Accretion			12,943				10,623				24,101				20,167
Field Services Operating Expense			2,648				1,265				6,703				2,721
Other Operating Expense (Income)			447				(33	)			891				294
TOTAL OPERATING EXPENSES			40,744				30,156				79,697				63,105
INCOME FROM OPERATIONS			14,616				101				23,132				985
OTHER INCOME (EXPENSE)
Interest Expense			(5,826	)			(1,583	)			(9,831	)			(3,322	)
Gain on Derivatives, Net			11,741				3,642				3,201				11,081
Other Income			2,213				92,731				2,073				92,737
Loss on Equity Method Investments			(183	)			(3,430	)			(361	)			(3,564	)
TOTAL OTHER INCOME (EXPENSE)			7,945				91,360				(4,918	)			96,932
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX			22,561				91,461				18,214				97,917
Income Tax Expense			(9,120	)			(35,268	)			(7,115	)			(37,899	)
INCOME FROM CONTINUING OPERATIONS			13,441				56,193				11,099				60,018
Income (Loss) From Discontinued Operations, Net of Income Taxes			520				(3,050	)			460				(8,405	)
NET INCOME			13,961				53,143				11,559				51,613
Net Income Attributable to Noncontrolling Interests			221				222				654				322
NET INCOME ATTRIBUTABLE TO REX ENERGY		$	13,740			$	52,921			$	10,905			$	51,291
Earnings per common share:
Basic – Net Income From Continuing Operations Attributable to Rex Common Shareholders		$	0.25			$	1.08			$	0.20			$	1.18
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders			0.01				(0.06	)			0.01				(0.16	)
Basic – Net Income Attributable to Rex Common Shareholders		$	0.26			$	1.02			$	0.21			$	1.02
Basic – Weighted Average Shares of Common Stock Outstanding			52,555				52,009				52,527				50,654
Diluted – Net Income From Continuing Operations Attributable to Rex Common Shareholders		$	0.25			$	1.06			$	0.20			$	1.16
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders			0.01				(0.06	)			0.01				(0.16	)
Diluted – Net Income Attributable to Rex Common Shareholders		$	0.26			$	1.00			$	0.21			$	1.00
Diluted – Weighted Average Shares of Common Stock Outstanding			52,911				52,876				52,901				51,567

 

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REX ENERGY CORPORATION

CONSOLIDATED OPERATIONAL HIGHLIGHTS

UNAUDITED

 

		Three Months Ending June  30,								Six Months Ending June 30,
		2013				2012				2013				2012
Oil, Natural Gas and NGL sales (in thousands):
Oil and condensate sales		$	19,653			$	15,223			$	37,786			$	32,323
Natural gas sales			23,505				10,152				40,315				21,425
Natural gas liquid sales			8,286				2,324				14,283				5,433
Cash-settled derivatives:
Crude oil			(172	)			(75	)			(333	)			(286	)
Natural gas			913				5,278				4,604				9,275
Natural gas liquids			386				93				527				93
Total oil, gas and NGL sales including cash settled derivatives		$	52,571			$	32,995			$	97,182			$	68,263
Production during the period:
Oil and condensate (Bbls)			213,716				169,194				411,831				341,391
Natural gas (Mcf)			5,453,725				4,216,175				10,243,603				8,325,347
Natural gas liquids (Bbls)			182,541				76,465				316,209				139,960
Total (Mcfe)a			7,831,267				5,690,129				14,611,843				11,213,453
Production – average per day:
Oil and condensate (Bbls)			2,349				1,859				2,275				1,876
Natural gas (Mcf)			59,931				46,332				56,594				45,744
Natural gas liquids (Bbls)			2,006				840				1,747				769
Total (Mcfe)a			86,061				62,529				80,276				61,614
Average price per unit:
Realized crude oil price per Bbl – as reported		$	91.96			$	89.97			$	91.75			$	94.68
Realized impact from cash settled derivatives per Bbl			(0.80	)			(0.44	)			(0.81	)			(0.84	)
Net realized price per Bbl		$	91.16			$	89.53			$	90.94			$	93.84
Realized natural gas price per Mcf – as reported		$	4.31			$	2.41			$	3.94			$	2.57
Realized impact from cash settled derivatives per Mcf			0.17				1.25				0.45				1.11
Net realized price per Mcf		$	4.48			$	3.66			$	4.39			$	3.68
Realized natural gas liquids price per Bbl – as reported		$	45.39			$	30.39			$	45.17			$	38.82
Realized impact from cash settled derivatives per Bbl			2.11				1.22				1.67				0.66
Net realized price per Bbl		$	47.50			$	31.61			$	46.84			$	39.48
LOE/Mcfeb		$	1.67			$	1.93			$	1.81			$	1.82

 

a	Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.

b	For the six months ended June 30, 2012, excludes the retroactive accrual of Pennsylvania Impact fee, which equates to approximately $0.25 per Mcfe

 

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REX ENERGY CORPORATION

COMMODITY DERIVATIVES – HEDGE POSITION AS OF AUGUST 2, 2013

 

		2013				2014				2015
Oil Derivatives (Bbls)
Swap Contracts
Volume			355,000				270,000	a			—
Price		$	93.38			$	96.82			$	—
Collar Contracts
Volume			30,000				60,000				—
Ceiling		$	97.00			$	97.65			$	—
Floor		$	92.00			$	90.00			$	—
Collar Contracts with Short Puts
Volume			30,000				360,000				—
Ceiling		$	100.00			$	104.27			$	—
Floor		$	85.00			$	85.35			$	—
Short Put		$	65.00			$	73.67			$	—
Put Spread Contracts
Volume			—				168,000				—
Floor		$	—			$	90.00			$	—
Short Put		$	—			$	75.00			$	—
Natural Gas Derivatives (Mcf)
Swap Contracts
Volume			4,920,000				4,830,000				1,200,000
Price		$	3.94			$	3.97			$	4.18
Swaption Contracts
Volume			600,000				1,200,000				—
Price		$	4.50			$	4.51			$	—
Collar Contracts
Volume			780,000				1,800,000				—
Ceiling		$	5.02			$	4.43			$	—
Floor		$	4.50			$	3.51			$	—
Put Spread Contracts
Volume			900,000				—				—
Ceiling		$	5.00			$	—			$	—
Floor		$	3.75			$	—			$	—
Put Contracts
Volume			1,320,000				—				—
Floor		$	5.00			$	—			$	—
Collar Contracts with Short Puts
Volume			1,260,000				7,800,000				2,400,000
Ceiling		$	4.88			$	4.68			$	4.63
Floor		$	4.17			$	4.02			$	4.16
Short Put		$	3.35			$	3.13			$	3.40
a)      Includes 240,000 Bbls of swaps with $80.00 short puts
Call Contracts
Volume			—				1,800,000				—
Ceiling		$	—			$	5.00			$	—
Natural Gas Liquids (Bbls)
Swap Contracts
Propane (C3)
Volume			106,000				21,000				—
Price		$	41.16			$	39.06			$	—
Butane (C4)
Volume			12,000				—				—
Price		$	66.36			$	—			$	—
Isobutane (IC4)
Volume			12,000				—				—
Price		$	69.72			$	—			$	—
Natural Gasoline (C5+)
Volume			57,000				12,000				—
Price		$	88.62			$	88.62			$	—

 

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APPENDIX

REX ENERGY COPRORATION

NON-GAAP MEASURES

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives non-recurring gains and losses, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

 

•

Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;

 

•

The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;

 

•

Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

 

•

The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

 

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To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented ($ in thousands):

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2013				2012				2013				2012
Net Income From Continuing Operations		$	13,441			$	56,193			$	11,099			$	60,018
Net Income Attributable to Noncontrolling Interests			(221	)			(222	)			(654	)			(322	)
Income From Continuing Operations Attributable to Rex Energy		$	13,220			$	55,971			$	10,445			$	59,696
Add Back Non-Recurring Lossesa			—				—				—				2,809
Add Back Depletion, Depreciation, Amortization and Accretion			12,943				10,884				24,101				20,686
Add Back Non-Cash Compensation Expense			1,160				362				2,423				841
Add Back Interest Expense			5,826				1,322				9,831				2,803
Add Back Impairment Expense			105				273				170				3,066
Add Back Exploration Expenses			2,225				1,213				4,269				2,305
Less Gain on Disposal of Assetsb			(751	)			(92,679	)			(760	)			(92,653	)
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives			(10,614	)			1,654				1,597				(2,000	)
Less Non-Cash Portion of Noncontrolling Interests			(152	)			(18	)			(206	)			(60	)
Add Back Income Tax Expense			9,120				35,268				7,115				37,899
Add Back Non-Cash Portion of Equity Method Investment			183				3,709				361				4,121
EBITDAX From Continuing Operations		$	33,265			$	17,959			$	59,346			$	39,513
Net Income (Loss) From Discontinued Operations			520				(3,050	)			460				(8,405	)
Add Back Non-Cash Compensation Expense			—				2				—				12
Add Back Impairment Expense			—				4,681				—				12,951
Add Back Exploration Expenses			44				149				97				481
Add Back (Less) Loss (Gain) on Disposal of Assets			(973	)			—				(969	)			144
Add Back (Less) Income Tax Expense (Benefit)			355				(2,123	)			313				(5,860	)
Add EBITDAX From Discontinued Operations		$	(54	)		$	(341	)		$	(99	)		$	(677	)
EBITDAX (Non-GAAP)		$	33,211			$	17,618			$	59,247			$	38,836

 

a)	Includes $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee for the six months ended June 30, 2012

b)	Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the three and six months ended June 30, 2012 and $2.2 million for the three and six months ended June 30, 2013

 

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Adjusted Net Income

“Adjusted Net Income” means, for any period, the sum of net income for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by Rex Energy’s management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Income is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company’s performance.

Rex Energy has reported Adjusted Net Income because it believes that this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Adjusted Net Income as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.

The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2013				2012				2013				2012
Income From Continuing Operations Before Income Taxes, as reported		$	22,561			$	91,461			$	18,214			$	97,917
Add Back Non-Recurring Losses			—				—				—				2,809
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives			(10,614	)			1,654				1,597				(2,000	)
Add Back Impairment Expense			105				273				170				3,066
Add Back Dry Hole Expense			485				52				485				306
Add Back Non-Cash Compensation Expense			1,160				362				2,423				841
Less Gain on Disposal of Assetsa			(751	)			(92,679	)			(760	)			(92,653	)
(Less) Income Attributable to Noncontrolling Interests			(221	)			(222	)			(654	)			(322	)
Income Before Income Taxes, adjusted		$	12,725			$	901			$	21,475			$	9,964
Less Income Taxes, adjustedb			5,192				349				8,697				3,866
Adjusted Net Income		$	7,533			$	552			$	12,778			$	6,098
Basic – Adjusted Net Income per Share		$	0.14			$	0.01			$	0.24			$	0.12
Basic – Weighted average shares of common stock outstanding			52,555				52,009				52,527				50,654

 

a	Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the three and six months ended June 30, 2012 and $2.2 million for the three and six months ended June 30, 2013

b	Income tax adjustment represents effective tax rate for the period.

 

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Cash General and Administrative Expenses

Cash General and Administrative Expenses (Cash G&A) is the difference between GAAP G&A and non-cash G&A, which is primarily comprised of non-cash compensation expense. Rex Energy has reported Cash G&A because it believes that this measure is commonly reported and widely used by management and investors as an indicator of overhead efficiency without regard to non-cash expenditures, such as stock compensation. Cash G&A is not a calculation based on GAAP financial measures and should not be considered as an alternative to GAAP G&A in measuring the company’s performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Cash G&A as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the company believes it is important to consider both Cash G&A and GAAP G&A. The following table presents a reconciliation of Rex Energy’s GAAP G&A to its Cash G&A for each of the periods presented (in thousands):

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2013				2012				2013				2012
GAAP G&A		$	7,782			$	5,774			$	15,578			$	11,185
Non-Cash Compensation			(1,160	)			(362	)			(2,423	)			(841	)
Cash G&A		$	6,622			$	5,412			$	13,155			$	10,344

 

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